Hydraulic fracturing is a common stimulation technique used to enhance production of hydrocarbon fluids from subterranean formations. In a typical hydraulic fracturing treatment, fracturing treatment fluid containing a solid proppant material is injected into the formation at a pressure sufficiently high enough to cause the formation to fracture or cause enlargement of natural fractures in the reservoir. The fracturing fluid that contains the proppant or propping agent typically has its viscosity increased by a gelling agent such as a polymer, which may be uncrosslinked or crosslinked, and/or a viscoelastic surfactant. During a typical fracturing treatment, propping agents or proppant materials are deposited in a fracture, where they remain after the treatment is completed. After deposition, the proppant materials serve to hold the fracture open, thereby enhancing the ability of fluids to migrate from the formation to the well bore through the fracture. Because fractured well productivity depends on the ability of a fracture to conduct fluids from a formation to a wellbore, fracture conductivity is an important parameter in determining the degree of success of a hydraulic fracturing treatment and the choice of proppant may be critical to the success of stimulation.
One problem related to hydraulic fracturing treatments is the creation of reservoir “fines” and associated reduction in fracture conductivity. These fines may be produced when proppant materials are subjected to reservoir closure stresses within a formation fracture which cause proppant materials to be compressed together in such a way that small particles (“fines”) are generated from the proppant material and/or reservoir matrix. In some cases, production of fines may be exacerbated during production/workover operations when a well is shut-in and then opened up. This phenomenon is known as “stress cycling” and is believed to result from increased differential pressure and closure stress that occurs during fluid production following a shut-in period. Production of fines is undesirable because of particulate production problems, and because of reduction in reservoir permeability due to plugging of pore throats in the reservoir matrix.
Production of particulate solids with subterranean formation fluids is also a common problem. The source of these particulate solids may be unconsolidated material from the formation, proppant from a fracturing treatment and/or fines generated from crushed fracture proppant, as mentioned above. Production of solid proppant material is commonly known as “proppant flowback.” In addition to causing increased wear on downhole and surface production equipment, the presence of particulate materials in production fluids may also lead to significant expense and production downtime associated with removing these materials from wellbores and/or production equipment. Accumulation of these materials in a well bore may also restrict or even prevent fluid production. In addition, loss of proppant due to proppant flowback may also reduce conductivity of a fracture pack.
It will be appreciated that if proppant strength can be improved that at least two problems are addressed. First, proppants with improved strength can better hold the fracture open to facilitate the production of hydrocarbon fluids. Second, stronger proppants do not disintegrate and exacerbate the production of fines. Thus, it would be very desirable to discover methods to produce stronger proppants.